EP1435529B1 - Méthode et dispositif pour traitement spectroscopique en fond de puits - Google Patents

Méthode et dispositif pour traitement spectroscopique en fond de puits Download PDF

Info

Publication number
EP1435529B1
EP1435529B1 EP02293281A EP02293281A EP1435529B1 EP 1435529 B1 EP1435529 B1 EP 1435529B1 EP 02293281 A EP02293281 A EP 02293281A EP 02293281 A EP02293281 A EP 02293281A EP 1435529 B1 EP1435529 B1 EP 1435529B1
Authority
EP
European Patent Office
Prior art keywords
downhole
processing
data
raw
downhole tool
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
Application number
EP02293281A
Other languages
German (de)
English (en)
Other versions
EP1435529A1 (fr
Inventor
Roger c/o Schlumberger SRPC Griffiths
Jack c/o Schlumberger SRPC Horkowitz
Kai c/o Schlumberger SRPC Hsu
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Services Petroliers Schlumberger SA
Original Assignee
Services Petroliers Schlumberger SA
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority to DE60215963T priority Critical patent/DE60215963T2/de
Application filed by Services Petroliers Schlumberger SA filed Critical Services Petroliers Schlumberger SA
Priority to EP02293281A priority patent/EP1435529B1/fr
Priority to AT02293281T priority patent/ATE344930T1/de
Priority to AU2003294720A priority patent/AU2003294720A1/en
Priority to MXPA05007044A priority patent/MXPA05007044A/es
Priority to RU2009107265/28A priority patent/RU2503979C2/ru
Priority to PCT/EP2003/013147 priority patent/WO2004059344A1/fr
Priority to US10/541,091 priority patent/US7342222B2/en
Priority to CNB2003801100810A priority patent/CN100337128C/zh
Priority to RU2005124271/28A priority patent/RU2005124271A/ru
Publication of EP1435529A1 publication Critical patent/EP1435529A1/fr
Application granted granted Critical
Publication of EP1435529B1 publication Critical patent/EP1435529B1/fr
Anticipated expiration legal-status Critical
Expired - Lifetime legal-status Critical Current

Links

Images

Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V5/00—Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity
    • G01V5/04—Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging
    • G01V5/045—Transmitting data to recording or processing apparatus; Recording data

Definitions

  • Well logs are measurements, typically with respect to depth, of selected physical parameters of earth formations penetrated by a wellbore.
  • Well logs are typically recorded by inserting various types of measurement instruments disposed on an integrated measurement platform into a wellbore, moving the instruments along the wellbore, and recording the measurements made by the instruments.
  • One type of well log recording includes lowering the instruments at the end of an armored electrical cable, and recording the measurements made with respect to the length of the cable extended into the wellbore. These are known as "wireline" measurements.
  • Depth within the wellbore is inferred from the extended length of the cable. Recordings made in this way are substantially directly correlated to measurement depth within the wellbore.
  • LWD logging while drilling
  • MWD measurement while drilling
  • MWD measurement while drilling
  • LWD and wireline tools are typically used to measure the same sort of formation parameters, such as density, resistivity, gamma ray, neutron porosity, sigma, ultrasonic measurement, etc.
  • MWD tools are typically used to measure parameters closely associated with drilling, such as well deviation, well azimuth, weight-on-bit, mud flow rate, annular borehole pressure, etc.
  • LWD and MWD measurement methods allow for measurement in the drill string while the bit is cutting, or measurement while tripping down or up past a section of a borehole that had been drilled at a previous time.
  • a major distinction between measurements taken using wireline tools and measurements taken using LWD/MWD tools is the ability to get the raw data back to the surface.
  • a wireline tool With a wireline tool, all of the raw data can be sent directly to the surface via the armored cable.
  • the typical means of communication between the tool and the surface is via mud pulse telemetry, wherein the pressure of the drilling fluid (mud) flowing through the interior of the drilling tool assembly is modulated to convey information. This is an extremely narrow bandwidth communication channel. Accordingly, only small amounts of information can be conveyed to the surface. Larger amounts of data must be stored in the tool for later retrieval at the surface.
  • US patent 5 539 225 A describes a measurement while drilling apparatus and methods to provide measurements of porosity, density and lithology and to detect gas.
  • the apparatus includes a 14 MeV neutron source accelerator and several neutron detectors at different distances from the source.
  • information as to the chemical composition of the formation may be obtained from a spectral analysis of gamma ray energy spectra recorded at an array gamma ray detector.
  • the bottom hole includes conventional acquisition and processing electronics storing data from the measuring sensors processing the data and storing the results, and coupling any desired portion of the data to the telemetry components for transmission to the surface.
  • the method indicates how to use the output of the neutrons detectors to determine some properties or composition of the surrounding earth formation..
  • Figure 1 shows a typical manner in which well log data are acquired in the wireline environment.
  • An assembly or "string” of well log instruments (including logging sensors or “sondes” (8, 5, 6 and 3) as will be further explained) is lowered into a wellbore (32) drilled through the earth (36) at one end of an armored electrical cable (33).
  • the cable (33) is extended into and withdrawn from the wellbore (32) by means of a winch (11) or similar conveyance known in the art.
  • the cable (33) transmits electrical power to the instruments (including logging sensors 8, 5, 6, 3) in the string, and communicates signals corresponding to measurements made by the instruments including logging sensors 8, 5, 6, 3) in the string to a recording unit (7) at the earth's surface.
  • the recording unit (7) includes a device (not shown) to measure the extended length of the cable (33). Depth of the instruments (including logging sensors 8, 5, 6, 3) within the wellbore (32) is inferred from the extended cable length.
  • the recording unit (7) includes equipment (not shown separately) of types well known in the art for making a record with respect to depth of the instruments within the wellbore (32).
  • the logging sensors (8, 5, 6, and 3) may be of any type known in the art. These include gamma ray sensors, neutron porosity sensors, electromagnetic induction resistivity sensors, nuclear magnetic resonance sensors, and gamma-gamma (bulk) density sensors. Some logging sensors, such as (8, 5, and 6) are contained in a sonde "mandrel" (axially extended cylinder) which may operate effectively near the center of the wellbore (32) or displaced toward the side of the wellbore (32). Others logging sensors, such as a density sensor (3), include a sensor pad (14) disposed to one side of the sensor housing (13) and have one or more detecting devices (17) therein.
  • the senor (3) includes a radiation source (18) to activate the formations proximate the wellbore (32). Such logging sensors are typically responsive to a selected zone (9) to one side of the wellbore (32).
  • the sensor (3) may also include a caliper arm (15), which serves both to displace the sensor (3) laterally to the side of the wellbore (32) and to measure an apparent internal diameter of the wellbore (32).
  • FIG. 2 shows a typical configuration for acquiring well log data using a logging while drilling (LWD) and measurements while drilling (MWD) system (39).
  • the LWD/MWD system (39) may include one or more collar sections (44, 42, 40, 38) coupled to the lower end of a drill pipe (20).
  • the LWD/MWD system (39) includes a drill bit (45) at the bottom end to drill the wellbore (32) through the earth (36).
  • drilling is performed by rotating the drill pipe (20) by means of a rotary table (43).
  • drilling may also be performed by top drives or coiled tubing drilling or downhole motors or with rotary steerable systems.
  • the pipe (20) is suspended by equipment on a drill rig (10) including a swivel (24), which enables the pipe (20) to rotate while maintaining a fluid tight seal between the interior and exterior of the pipe (20).
  • Mud pumps (30) draw drilling fluid ("mud") (26) from a tank or pit (28) and pump the mud (26) through the interior of the pipe (20), down through the LWD/MWD system (39), as indicated by arrow (41).
  • the mud (26) passes through orifices (not shown) in the bit (45) to lubricate and cool the bit (45), and to lift drill cuttings through an annulus (34) between the pipe (20), LWD/MWD system (39), and the wellbore (32).
  • the collar sections (44, 42, 40, 38) include logging sensors (not shown) which make measurements of various properties of the earth formations through which the wellbore (32) is drilled. These measurements are typically recorded in a recording device (not shown) disposed in one or more of the collar.
  • LWD systems known in the art typically include one or more logging sensors (not shown) which measure formation parameters, such as density, resistivity, gamma ray, neutron porosity, sigma, etc. as described above, which may be used to determine formation lithology, etc.
  • MWD systems known in the art typically include one or more logging sensors (not shown) which measure selected drilling parameters, such as inclination and azimuthal trajectory of the wellbore (32). MWD systems also provide the telemetry (communication system) for any MWD/LWD tool logging sensors in the drill string.
  • the LWD/MWD system (39) typically includes a mud pressure modulator (not shown separately) in one of the collar sections (44).
  • the modulator applies a telemetry signal to the flow of mud (26) inside the system (39) and pipe (20) where the telemetry signal is detected by a pressure sensor (31) disposed in the mud flow system.
  • the pressure sensor (31) is coupled to detection equipment (not shown) in the surface recording system (7A), which enables recovery and recording of information transmitted in the telemetry scheme sent by the MWD portion of the LWD/MWD system (39).
  • the telemetry scheme includes a subset of measurements made by the various logging sensors (not shown separately) in the LWD/MWD system (39). The majority of the measurements made by the logging sensors in the LWD/MWD system (39) are not retrieved until the system is withdrawn from the wellbore.
  • lithology refers to the physical character and composition of the rock.
  • a lithologic log indicates the different rock strata within the formations penetrated by the borehole.
  • a lithologic log may be produced by obtaining formation spectroscopy data using a wireline neutron tool, and subsequently processing the data at the surface to provide the desired log.
  • this process is of no use while the hole is being drilled.
  • To give the drilling operator a picture of the lithology as the hole is being drilled it is conventional to examine the drill cuttings brought to the surface by the circulated drilling mud. This process generates what is known as a "mud log".
  • FIG. 3 An example of a conventional, manually-generated mud log is shown in Figure 3.
  • drilling time is recorded in area 51 at 2-foot intervals, and time is recorded in minutes per foot. This information is important as it gives the operator information some basic information about what type of rock is being drilled through (some rocks, e.g., shales, drill "slow", while others, e.g., limestone, drill "fast”).
  • the mud logger uses standard symbols and colors to indicate the type of rock that is being drilled based upon the well cuttings.
  • the mud logger provides a written description of the samples he or she has examined. The last step is for the mud logger to pick and note formation horizons. On this log, the "L-1", L-2", and "Neva" formations are indicated.
  • FIG. 4 An example of a more modem yet conceptually analogous mud log is shown in Figure 4.
  • the drilling time data in area 51 and the pictorial representation of the lithology in area 53 are generated by computer.
  • the mud logger still has to manually examine the cuttings to provide the notations in area 55.
  • conventional mud logs have certain limitations. For example, as the depth of the hole increases, the latency of the log, i.e., the time between when the actual cutting occurs and when the corresponding cuttings are circulated to the surface, becomes large. In addition, the cuttings from different depths may become commingled in the mud, giving an inaccurate representation of the formation.
  • spectroscopy-derived lithology information may be obtained using a wireline tool.
  • the entire measured gamma-ray energy spectrum is transmitted to the surface, where it is processed to derive elemental yields and subsequent lithological indicators. This is possible in the wireline environment because of the transmission bandwidth available through the electrical conductors of the wireline.
  • Information obtained from the mud log typically will be considered together with information obtained using wireline tools to determine whether to complete the hole.
  • spectroscopy processing requires a large amount of raw data; an amount of data that greatly exceeds the transmission bandwidth in a typical LWD/MWD system.
  • conventional spectroscopy processing requires operator input to guide the processing and ultimately produce a lithology model. For both of these reasons, in the LWD/MWD environment, spectroscopy processing is something that conventionally has only been done at the surface and after the tool has been retrieved from the hole.
  • FIG. 5 shows a flow diagram of the typical steps involved in surface spectroscopy processing.
  • the raw spectral data is acquired by a downhole tool (Step 400).
  • the downhole tool may include such tools as a Reservoir Saturation Tool (RST), a Combinable Production Logging Tool (CPLT), etc. (RST and CPLT are marks of Schlumberger).
  • RST Reservoir Saturation Tool
  • CPLT Combinable Production Logging Tool
  • the raw spectral data is then pre-processed (Step 402).
  • Pre-processing includes determining foreground and background spectra as well as accumulation and background subtraction.
  • the result of the pre-processing is a net capture spectrum.
  • the net capture spectrum is subsequently processed using spectral stripping (Step 404).
  • the elemental yields, offsets, and gains are calculated using the net capture spectra and the depth information (406).
  • the results from the spectral processing are then used for borehole logic processing (Step 408).
  • depth information (406) and data from other well logging tools (410) may be used in conjunction with the spectroscopy information to identify the composition of the drilling mud system, and allow for corrections to be made as necessary.
  • user intervention (412) may be required to facilitate the borehole logic processing.
  • the elemental yields calculated during spectral stripping (Step 404) are re-distributed, as required, based on the results of the borehole logic processing (Step 414).
  • the re-distributed yields are then used in pre-spectroscopy to lithology processing to correct the calculated sulfur and iron yields, filter the elemental yields, compute the apparent salinity, and baseline certain yields in preparation for further processing (416).
  • Oxides closure processing is subsequently performed to determine the dry weight elemental concentrations of particular elements, such as silicon, calcium, sulfur, iron, titanium, etc. (Step 418).
  • the dry weight elemental concentrations are then used in spectroscopy-to-lithology processing to determine the dry weights of clay, carbonate, quartz-feldspar-mica (QFM), pyrite, anhydride, siderite, salt and coal (Step 420).
  • the dry weight elemental concentrations and calculated lithology fractions are also used in formation logic processing to determine the appropriate clay model (e.g ., arenite, sub-arkose, arkose, etc.), sulfur mineral model, and presence of siderite, coal and salt (Step 422).
  • Step 420 The results from the spectroscopy-to-lithology processing (Step 420) and the formation logic processing (Step 422) are used to compute matrix properties (Step 424), such as matrix density, matrix neutron, matrix sigma, matrix photoelectric factor, etc.
  • matrix properties such as matrix density, matrix neutron, matrix sigma, matrix photoelectric factor, etc.
  • the uncertainties for the dry weight of the elements are subsequently calculated to ensure the robustness of the above calculations (Step 426).
  • the invention in general, in one aspect, relates to a method for downhole spectroscopy processing comprising: obtaining raw spectroscopy data using a downhole tool; processing the raw spectroscopy data using the downhole tool to obtain an downhole processed solution; transmitting the downhole processed solution to a surface processing system; and using the surface processing system to determine lithology information from the downhole processed solution.
  • the invention in general, in another aspect, relates to a downhole tool for processing raw spectroscopy data, comprising: a neutron source; at least one detector for detecting the raw spectroscopy data; processing means for processing the raw spectroscopy data to produce a downhole processed solution; and means for transmitting the downhole processed solution to a surface location.
  • Figure 1 shows typical well log data acquisition using a wireline-conveyed instrument.
  • Figure 2 shows typical well log data acquisition using a logging while drilling/measurement while drilling system.
  • Figure 3 shows an example of a manual mud log
  • Figure 4 shows an example of a computer-generated mud log.
  • Figure 5 shows a flow diagram of the typical steps involved in surface spectroscopy processing.
  • Figure 6 illustrates a downhole spectroscopy processing system in accordance with one embodiment of the invention.
  • Figure 7 illustrates acquisition and processing circuitry in accordance with the embodiment of Figure 6.
  • FIG. 8 illustrates a flow diagram in accordance with one embodiment of the invention.
  • Figure 9 illustrates a user interface in accordance with one embodiment of the invention.
  • lithological information may be determined by transmitting the entire measured gamma-ray energy spectrum to the surface and processing it there.
  • the LWD/MWD environment due to the limited bandwidth communication channel available, makes it difficult if not impossible to use the above-mentioned technique.
  • data compression techniques must be implemented downhole to reduce the amount of information transmitted to the surface.
  • One of the most powerful compression techniques is to convert the raw measurements into intermediate information as close as possible to the information required by the final user.
  • the embodiments of the invention described herein provide downhole processing of spectroscopy data with increased processing power in the downhole tool.
  • the downhole tool includes processing logic that allows it to run automatically independent of user intervention and certain other external variables, making it possible to perform the spectral stabilization, stripping and subsequent interpretive processing before the data transfer bottleneck of the mud-pulse telemetry system.
  • processing logic that allows it to run automatically independent of user intervention and certain other external variables, making it possible to perform the spectral stabilization, stripping and subsequent interpretive processing before the data transfer bottleneck of the mud-pulse telemetry system.
  • One advantage is that, rather than transmitting the entire spectrum, derived products (such as lithology proportions and grain responses) are transmitted using substantially fewer bits than would be required for the full spectrum.
  • a downhole processed solution of the invention may be a final product of interest to the user.
  • the downhole processed solution may be an intermediate product that will serve as a basis for further processing at the surface.
  • FIG. 6 illustrates a downhole spectroscopy processing system in accordance with one embodiment of the invention.
  • the system comprises a downhole portion and a surface portion.
  • the downhole portion is designed to be placed on board in a downhole tool (449).
  • the downhole tool may be, for example, an LWD or MWD tool such as that illustrated in prior art Figure 2.
  • the particular design and characteristics of the tool are not germane here provided that the tool incorporates basic functionality, namely, a source of high energy neutrons from either a Pulsed Neutron Generator (PNG) (451) or a chemical source, and the appropriate sensors to detect the gamma-ray energy spectrum (shown as sensors 453a through 453n).
  • PNG Pulsed Neutron Generator
  • the downhole portion of the system also includes an acquisition and processing electronics module (455), described in more detail below.
  • the surface portion of the system of this embodiment comprises a communication interface (72) that permits the surface portion to receive and decode information sent by the downhole portion, in addition to a processor (74), a display (82), and an input means (e.g., a keyboard) (78).
  • a communication interface (72) that permits the surface portion to receive and decode information sent by the downhole portion, in addition to a processor (74), a display (82), and an input means (e.g., a keyboard) (78).
  • a processor 74
  • a display 82
  • an input means e.g., a keyboard
  • the surface portion of the system may take the form of an ordinary personal computer, or may be a specialized design.
  • the surface portion may comprise a stand-alone computer dedicated to the functionality of this invention, or it may be implemented in a general use system that controls other drilling-related functions.
  • the acquisition and processing electronics module (455) is shown in detail in Figure 7.
  • the module (455) is divided into acquisition and control electronics (501) and a spectroscopy processing module (510).
  • the acquisition and control electronics of this embodiment include a resistivity module (500), an Ultra Sonic & Azimuthal module (502), a Cesium Gamma module (503), a Pulsed Neutron Generator (PNG) Timing module (504), a PNG Gamma module (506), and a PNG Neutron module (508).
  • the PNG Timing module (504) controls the firing of the PNG and synchronizes the PNG gamma module (506) for spectroscopic acquisition.
  • the acquired spectroscopy data is transferred to the spectroscopy processing module (510) via the data bus (512).
  • Control functionality is provided by a process controller (522) and a memory controller (524). Both controllers (552, 524) communicate with the other components ( i.e ., 502-506) via the data bus (512).
  • the spectroscopy processing module (510) includes a processing interface (514), such as a control area network (CAN) transceiver, CAN controller, etc.
  • the processing interface (514) facilitates data transfer between the other components (i.e., 502-506) of the acquisition electronics (501) and the spectroscopy processing module (510).
  • the processing interface (514) is connected to a digital signal processor (DSP) (516).
  • DSP digital signal processor
  • the DSP may be of any appropriate type, for example, a 32-bit floating point DSP.
  • the DSP is used to process the acquired spectroscopy data and generate various levels of spectral processing results, or a downhole processed solution.
  • a local memory (518), connected to the digital signal processor (516) is used, as required, by the DSP (516) in the generation of the downhole processed solution.
  • the spectroscopy processing module (510) is powered by a local power supply (520) that is connected to the DSP.
  • the downhole processed solution may be transmitted to the surface via an external port (526) that is connected to the process controller (522) and the memory controller (524).
  • the transmission to the surface is via any conventional or non-conventional means, e.g., mud pulse , wired drillpipe, or other types of telemetry.
  • Figure 8 illustrates a flow diagram in accordance with one embodiment of the invention.
  • the raw spectral data is acquired by the downhole tool (Step 600). As the raw spectral data is acquired, it is time-stacked to maintain the order in which each portion of the raw spectral data was acquired with respect to time.
  • the raw spectral data is then pre-processed (Step 602).
  • the pre-processing includes determining foreground and background spectra as well as accumulation and background subtraction.
  • the result of the pre-processing is a net capture spectrum, which is subsequently processed using spectral stripping (Step 604).
  • the relative yields, offsets, and gains are calculated using the net capture spectra, a set of elemental standards, tool calibration and the time information (Step 606) (e.g ., information necessary to convert the time stacked data into data correlated with a depth, such as rate of penetration, start time, etc.).
  • Certain results from the spectral stripping are then corrected during pre-spectrolithology processing based on the results of the borehole processing logic results, such as the correction of the sulfur yield for barite in the drilling mud system, followed by filtering of elemental yields previously calculated (Step 608).
  • Oxides closure processing is subsequently performed to determine the dry weight elemental concentrations of particular elements, such as silicon, calcium, sulfur, iron, aluminum, etc (Step 610).
  • the dry weight elemental concentrations are then used in spectrolithology processing to determine the dry weights of clay, carbonate, quartz-feldspar-mica (QFM), pyrite, anhydride, siderite, salt and coal (Step 612).
  • QFM quartz-feldspar-mica
  • pyrite anhydride, siderite, salt and coal
  • sulfur mineral processing is initially performed to compute the dry weight of anhydrite and/or pyrite (Step 612a).
  • the dry weight of anhydrite, in addition to the elemental concentrations of silicon, calcium, and iron are used in clay processing (Step 612b).
  • a clay model (612e) is approximated and used to determine the dry weight of clay.
  • QFM is subsequently calculated using QFM processing (Step 612d).
  • Step 612 The results from the spectrolithology processing (Step 612) are used to compute matrix properties (Step 614), such as matrix density, matrix neutron, matrix sigma, matrix photoelectric factor, etc.
  • matrix properties such as matrix density, matrix neutron, matrix sigma, matrix photoelectric factor, etc.
  • the uncertainties for the dry weight of the elements are subsequently calculated to ensure the robustness of the above calculations (Step 616).
  • a downhole processed solution has been obtained that has a significantly small bandwidth and is readily transmitted to the surface in real-time (618).
  • the downhole processed solution is a preliminary estimate of the downhole lithology that can be accurately determined using spectral analysis. Borehole logic and yield redistribution typically would not be performed downhole because these processes typically require data from other sensors that may not sample the same formation at the same time as the spectroscopy tools.
  • a surface processing system uses the downhole processed solution along with depth-aligned data from other well logging tools (622) to determine whether lithologies that cannot be detected in a robust manner by spectroscopy alone are present. If data from the additional well logging tools (622) indicates the presence of such lithologies, user intervention (624) is required. User intervention is necessary to determine the type of processing to be applied to the downhole processed solution such that the final formation lithology is consistent with data acquired from all well logging tools currently being used at the wellsite.
  • the surface processing system (620) initially re-computes the QFM concentration using surface QFM processing (Step 620a). Coal processing (Step 620b) and salt processing (Step 620c) are subsequently performed as required.
  • the results of the individual processing components (i.e ., steps 620a-620c) in the surface processing system (620) are combined to produce the final formation lithology (Step 620d).
  • each of the individual surface processing components may require data from one or more additional well logging tools (622). Further, the individual surface processing components may require user intervention at one or more times during the course of the processing.
  • the lithology information may be displayed as a strip of various colors of varying widths to indicate the proportions of the lithologies in the section of formation surveyed by the logging system.
  • the outputs of the above-described downhole processing system are displayed to the drilling operator via a user interface.
  • FIG. 9 An example of a user interface in accordance with one embodiment of the invention is shown in Figure 9.
  • a drilling operator user interface is shown in area 57.
  • area 59 information that is traditionally transmitted in real;-time is shown.
  • caliper and Gamma Ray information are displayed.
  • area 61 the derived lithology information is graphically displayed.
  • Embodiments of the invention may have one or more of the following advantages.
  • the invention provides the ability to obtain a downhole processed solution by providing automated downhole processing.
  • the downhole processed solution requires a substantially small bandwidth for transfer to the surface.
  • the substantially small bandwidth allows the downhole processed solution to be viewed in real-time at the surface.
  • Embodiments of the invention allow automation of borehole corrections and the selection of appropriate formation mineralogy components. This is accomplished through the use of a suite of algorithms that utilize the spectroscopy and/or additional measurements as necessary. In contrast, most of the existing spectroscopy processing algorithms require the user to manually select from a suite of possible corrections to be made for the borehole fluid system and also select the formation mineral components to solve for, resulting in highly subjective and frequently inaccurate results.

Landscapes

  • Physics & Mathematics (AREA)
  • High Energy & Nuclear Physics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • General Physics & Mathematics (AREA)
  • Geophysics (AREA)
  • Analysing Materials By The Use Of Radiation (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • Investigating Or Analysing Materials By Optical Means (AREA)
  • Earth Drilling (AREA)

Claims (13)

  1. Méthode pour traitement spectroscopique comportant. : à
    à) l'obtention de données spectroscopiques brutes (ST 600) à l'aide d'un outil de fond de puits
    b) le traitement des données spectroscopiques brutes à l'aide de l'outil de fond de puits pour déterminer les informations lithologiques ;
    c) la transmission des données brutes et/ou des données traitées à un système de traitement en surface, caractérisée en ce que la méthode comporte, à l'étape b),
    l'obtention d'une solution traitée en fond de puits par b1) un prétraitement (ST 608) en fond de puits des données spectroscopiques brutes pour obtenir un spectre de capture net
    et
    b2) la réalisation en fond de puits d'une soustraction spectrale (ST :604) en utilisant des informations temporelles et le spectre de capture net pour déterminer des rendements élémentaires, et comprenant en outre à l'étape c),
    c1) la transmission (ST 618) de la solution traitée en fond de puits à un système de traitement en surface (620),
    d) l'utilisation (ST 620a à d) du système de traitement en surface (620) pour déterminer les informations lithologiques à partir de la solution traitée en fond de puits.
  2. Méthode selon la revendication 1, le prétraitement comportant la migration en temps (606) des données spectroscopiques brutes.
  3. Méthode selon la revendication 1 ou 2, comprenant en outre la comparaison de la solution traitée en fond de puits à des données obtenues d'un autre outil de fond de puits (622).
  4. Méthode selon l'une quelconque des revendications 1 à 3, comprenant en outre l'affichage (620d) des informations lithologiques sur une interface utilisateur.
  5. Méthode selon l'une quelconque des revendications 1 à 4, le traitement des données spectroscopiques brutes comprenant en outre ;
    la détermination (ST 610, 612a à d) des concentrations massiques élémentaires à sec à l'aide des rendements élémentaires ;
    la détermination d'une masse sèche (ST 610, 612a à d) pour au moins un composant choisi parmi le groupe constitué de l'argile, le carbonate, le quartz-feldspath-mica, la pyrite, l'anhydride, la sidérite, le sel et le charbon à l'aide des concentrations massiques élémentaires à sec ; et
    le calcul (ST 614) d'une propriété matricielle à l'aide des concentrations massiques élémentaires à sec.
  6. Outil de fond de puits destiné à traiter les données spectroscopiques brutes, comportant :
    au moins un détecteur (453a à n) destiné à détecter les données spectroscopiques brutes ;
    des moyens de traitement (455) destinés à traiter en fond de puits les données spectroscopiques brutes pour déterminer les informations lithologiques
    des moyens de transmission des données à un système de traitement en surface,
    caractérisé en ce que les moyens de traitement comportent
    des moyens (455) pour produire une solution traitée en fond de puits ;
    lesdits moyens comportant :
    des moyens (501) de prétraitement en fond de puits des données spectroscopiques brutes pour obtenir un spectre de capture net;
    des moyens (516) pour réaliser en fond de puits une soustraction spectrale utilisant les informations temporelles et le spectre de capture net pour déterminer des rendements élémentaires,
    et où les moyens de transmission des données à un système de traitement en surface (72, 74, 78, 82)
    transmettent la solution traitée en fond de puits,
  7. Outil de fond de puits selon la revendication 6, les moyens de traitement comportant des moyens de détermination des rendements élémentaires.
  8. Outil de fond de puits selon la revendication 6 ou 7. les moyens de traitement comportant des moyens de calcul d'une propriété matricielle.
  9. Outil de fond de puits selon l'une quelconque, des revendications 6 à 8, les moyens de traitement (510) comportant
    des moyens (516, 518) de détermination des concentrations massiques élémentaires à sec à l'aide des rendements élémentaires.
  10. Outil de fond de puits selon la revendication 9, les moyens de traitement comportant en outre :
    des moyens (516, 518) de détermination d'une masse sèche pour au moins un composant choisi parmi le groupe constitué de l'argile, le carbonate, le quartz-feldspath-mica, la pyrite, l'anhydride, la sidérite, le sel et le charbon à l'aide des concentrations massiques élémentaires à sec et
    des moyens (516, 518) de calcul d'une propriété matricielle à l'aide de la masse sèche.
  11. Outil de fond de puits selon l'une quelconque des revendications 6 à 10, les moyens de traitement comportant :
    un processeur de signal numérique (516) ;
    une alimentation (520) reliée fonctionnellement au processeur de signal numérique (516) ;
    une mémoire locale (518) reliée fonctionnellement au processeur de signal numérique (516); et
    une interface de traitement (514) reliée fonctionnellement au processeur de signal numérique (516).
  12. Système de mesures lithologiques en temps réel, comportant :
    un processeur en surface (74) ,
    des moyens (526, 72) de transmission de données brutes et de données traitées depuis l'outil de fond de puits au processeur en surface ;
    caractérisé en ce qu'il comporte :
    un outil de fond de puits selon l'une quelconque des revendications 6 à 11 pour produire une solution traitée en fond de puits et ;
    la transmission, par les moyens (526, 72) de transmission de données brutes et de données traitées, de la solution traitée en fond de puits au processeur en surface (74) et ;
    le processeur en surface comportant des moyens de détermination des informations lithologiques à partir de la solution traitée en fond de puits.
  13. Système selon la revendication 12, comportant en outre une interface utilisateur (78, 82) ; les informations lithologiques étant affichées sur l'interface utilisateur (82).
EP02293281A 2002-12-31 2002-12-31 Méthode et dispositif pour traitement spectroscopique en fond de puits Expired - Lifetime EP1435529B1 (fr)

Priority Applications (10)

Application Number Priority Date Filing Date Title
EP02293281A EP1435529B1 (fr) 2002-12-31 2002-12-31 Méthode et dispositif pour traitement spectroscopique en fond de puits
AT02293281T ATE344930T1 (de) 2002-12-31 2002-12-31 Verfahren und vorrichtung zur spektroskopischen verarbeitung von daten im bohrloch
DE60215963T DE60215963T2 (de) 2002-12-31 2002-12-31 Verfahren und Vorrichtung zur spektroskopischen Verarbeitung von Daten im Bohrloch
MXPA05007044A MXPA05007044A (es) 2002-12-31 2003-11-21 Metodo y aparato para procesamiento de espectrocospia en fondo de pozo.
RU2009107265/28A RU2503979C2 (ru) 2002-12-31 2003-11-21 Способ и устройство для обработки спектроскопических данных в скважине
PCT/EP2003/013147 WO2004059344A1 (fr) 2002-12-31 2003-11-21 Procede et appareil pour le traitement par spectroscopie de fond de puits
AU2003294720A AU2003294720A1 (en) 2002-12-31 2003-11-21 Method and apparatus for downhole spectroscopy processing
US10/541,091 US7342222B2 (en) 2002-12-31 2003-11-21 Method and apparatus for downhole spectroscopy processing
CNB2003801100810A CN100337128C (zh) 2002-12-31 2003-11-21 井下频谱处理方法、井下工具以及实时岩性测量系统
RU2005124271/28A RU2005124271A (ru) 2002-12-31 2003-11-21 Способ и устройство для обработки спектроскопических данных в скважине

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
EP02293281A EP1435529B1 (fr) 2002-12-31 2002-12-31 Méthode et dispositif pour traitement spectroscopique en fond de puits

Publications (2)

Publication Number Publication Date
EP1435529A1 EP1435529A1 (fr) 2004-07-07
EP1435529B1 true EP1435529B1 (fr) 2006-11-08

Family

ID=32479834

Family Applications (1)

Application Number Title Priority Date Filing Date
EP02293281A Expired - Lifetime EP1435529B1 (fr) 2002-12-31 2002-12-31 Méthode et dispositif pour traitement spectroscopique en fond de puits

Country Status (9)

Country Link
US (1) US7342222B2 (fr)
EP (1) EP1435529B1 (fr)
CN (1) CN100337128C (fr)
AT (1) ATE344930T1 (fr)
AU (1) AU2003294720A1 (fr)
DE (1) DE60215963T2 (fr)
MX (1) MXPA05007044A (fr)
RU (2) RU2503979C2 (fr)
WO (1) WO2004059344A1 (fr)

Families Citing this family (14)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8101907B2 (en) * 2006-04-19 2012-01-24 Baker Hughes Incorporated Methods for quantitative lithological and mineralogical evaluation of subsurface formations
US7511266B1 (en) * 2006-12-06 2009-03-31 Bothner Ronald E Irradiated formation tool (IFT) apparatus and method
US8284073B2 (en) * 2008-04-17 2012-10-09 Schlumberger Technology Corporation Downlink while pumps are off
US7772545B2 (en) * 2008-07-24 2010-08-10 Halliburton Energy Services, Inc. Nuclear logging tool
US10302811B2 (en) * 2008-08-21 2019-05-28 Weatherford Technology Holdings, Llc Data reduction of images measured in a borehole
MX2013002772A (es) * 2010-09-16 2013-07-29 Halliburton Energy Serv Inc Herramienta de registro de pozo revestido de neutrones sonico / pulsado combinado.
CN102425410A (zh) * 2011-10-11 2012-04-25 西南石油大学 一种随钻测量超声波数据传输方法及装置
CN102979515B (zh) * 2012-12-06 2015-06-24 武汉海阔科技有限公司 一种存储式测井系统
CN104329075B (zh) * 2014-09-05 2017-01-18 西安奥华电子仪器股份有限公司 元素测井中元素俘获标准谱的获取方法
US9696454B1 (en) * 2016-01-06 2017-07-04 Baker Hughes Incorporated Identifying weighting material sag with pulsed neutron logs
US10392919B2 (en) * 2016-03-23 2019-08-27 Baker Hughes, A Ge Company, Llc Simulated core sample estimated from composite borehole measurement
US9746582B1 (en) * 2016-04-21 2017-08-29 Schlumberger Technology Corporation Method for improving precision of neutron induced gamma ray spectroscopy
WO2018075056A1 (fr) * 2016-10-21 2018-04-26 Halliburton Energy Services, Inc. Systèmes et procédés de diagraphie photoélectrique géochimique
WO2021108847A1 (fr) * 2019-12-02 2021-06-10 Reflex Instruments Asia Pacific Pty Ltd Système de mesure conçu pour l'usage prévu pour diagraphie de trou de forage

Family Cites Families (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
SU407258A1 (ru) * 1972-01-06 1973-11-21 Литоры изобретени Аппаратура для каротажа скважин
DE2861278D1 (en) * 1978-06-05 1982-01-14 Stefa Industri Ab Sealing device for bearings, especially roll bearings
US4464569A (en) * 1981-06-19 1984-08-07 Schlumberger Technology Corporation Method and apparatus for spectroscopic analysis of a geological formation
US5086224A (en) * 1990-11-13 1992-02-04 Schlumberger Technology Corporation Analysis of nuclear data for determining characteristics of earth formations traversed by a borehole
US5539225A (en) * 1994-09-16 1996-07-23 Schlumberger Technology Corporation Accelerator-based methods and apparatus for measurement-while-drilling
RU2085734C1 (ru) * 1995-10-24 1997-07-27 Научно-производственная фирма "Оптоойл" Способ каротажного исследования буровых скважин при поиске полезных ископаемых и минералов
WO1998017894A2 (fr) * 1996-10-22 1998-04-30 Baker Hughes Incorporated Dispositif de forage a ensemble fond de puits integre
US6727696B2 (en) * 1998-03-06 2004-04-27 Baker Hughes Incorporated Downhole NMR processing
US6571619B2 (en) * 2001-10-11 2003-06-03 Schlumberger Technology Corporation Real time petrophysical evaluation system

Also Published As

Publication number Publication date
MXPA05007044A (es) 2005-10-18
US7342222B2 (en) 2008-03-11
DE60215963T2 (de) 2007-08-02
US20060091307A1 (en) 2006-05-04
CN100337128C (zh) 2007-09-12
EP1435529A1 (fr) 2004-07-07
DE60215963D1 (de) 2006-12-21
CN1756967A (zh) 2006-04-05
ATE344930T1 (de) 2006-11-15
RU2009107265A (ru) 2010-09-10
RU2005124271A (ru) 2006-01-27
WO2004059344A1 (fr) 2004-07-15
RU2503979C2 (ru) 2014-01-10
AU2003294720A1 (en) 2004-07-22

Similar Documents

Publication Publication Date Title
US6885942B2 (en) Method to detect and visualize changes in formation parameters and borehole condition
CA2583865C (fr) Amelioration de la qualite de la resolution d'une image generee a partir d'une seule source ou de multiples sources
US8217337B2 (en) Evaluating a reservoir formation
US20120192640A1 (en) Borehole Imaging and Formation Evaluation While Drilling
EP1435529B1 (fr) Méthode et dispositif pour traitement spectroscopique en fond de puits
EP1435429B1 (fr) Procédé et dispositif pour analyse avec délai de la cause et de l'effet
US20230105670A1 (en) Surface logging with cuttings-based rock petrophysics analysis
WO2007089338A2 (fr) Procédé et appareil de détection d'afflux de fluide au cours du forage
US20120084009A1 (en) Refined lithology curve
US9316764B2 (en) Downhole tool for determining formation properties
US11215732B2 (en) Geological constraint using probability functions in stochastic mineralogy modeling
WO2020214222A1 (fr) Acquisition de données rmn pendant la commutation d'ensembles d'activation rmn
US4527058A (en) Earth formation density measurement from natural gamma ray spectral logs
US20080156975A1 (en) Multi-evaluation core logger
WO2020149824A1 (fr) Rendu de trou de forage azimutal de données gamma spectrales de radioéléments
US11079513B2 (en) Evaluation of formation composition using neutron induced gamma spectroscopy tools
US20230060188A1 (en) Deep Learning Holdup Solution From Neutron Capture And Inelastic Scattering
EP2107396A1 (fr) Mesure sigma de fond de trou
US20210373190A1 (en) Evaluation and visualization of azimuthal resistivity data

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR IE IT LI LU MC NL PT SE SI SK TR

AX Request for extension of the european patent

Extension state: AL LT LV MK RO

17P Request for examination filed

Effective date: 20050105

AKX Designation fees paid

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR IE IT LI LU MC NL PT SE SI SK TR

GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR IE IT LI LU MC NL PT SE SI SK TR

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT;WARNING: LAPSES OF ITALIAN PATENTS WITH EFFECTIVE DATE BEFORE 2007 MAY HAVE OCCURRED AT ANY TIME BEFORE 2007. THE CORRECT EFFECTIVE DATE MAY BE DIFFERENT FROM THE ONE RECORDED.

Effective date: 20061108

Ref country code: BE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: NL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: CH

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: LI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REF Corresponds to:

Ref document number: 60215963

Country of ref document: DE

Date of ref document: 20061221

Kind code of ref document: P

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20061231

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20070102

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070208

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070208

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070208

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: ES

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070219

REG Reference to a national code

Ref country code: GB

Ref legal event code: 732E

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070409

NLV1 Nl: lapsed or annulled due to failure to fulfill the requirements of art. 29p and 29m of the patents act
REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

EN Fr: translation not filed
PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

26N No opposition filed

Effective date: 20070809

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: FR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070622

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20070209

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20061231

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: FR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20061108

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: DE

Payment date: 20091224

Year of fee payment: 8

REG Reference to a national code

Ref country code: DE

Ref legal event code: R119

Ref document number: 60215963

Country of ref document: DE

Effective date: 20110701

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20110701

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20211111

Year of fee payment: 20

REG Reference to a national code

Ref country code: GB

Ref legal event code: PE20

Expiry date: 20221230

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GB

Free format text: LAPSE BECAUSE OF EXPIRATION OF PROTECTION

Effective date: 20221230

P01 Opt-out of the competence of the unified patent court (upc) registered

Effective date: 20231208